Overview

Coiled-tubing drilling (CTD) has a rather extensive history and received a large amount of press and hype from the 1990s to date, a significant amount being less than positive. There have been numerous highly successful applications of CTD technology in such regions as Alaska and the United Arab Emirates, yet CTD is still considered an immature new technology. Reasons for this reputation are numerous and include:

Lack of understanding of CTD technology

Misapplication

Exaggerated expectations

One example of exaggerated expectations is CTD’s reputation for offering certain advantages, including small footprint, high mobility, and quick operations. These advantages may exist in situations such as:

Conventional coil-tubing services

Simple, short CTD jobs for which

Directional control is not required

The hole can be left uncased

However, when more complex CTD services are planned, including directional drilling and cased completions, these advantages may no longer apply. The complex drilling operations routinely require:

Pipe handling equipment

Provisions for handling long bottomhole assemblies (BHAs)

Large diameter coil-tubing (CT)

Larger blowout preventer (BOP) stacks, and

Fluid-handling equipment for:

Cleaning

Mixing

Recirculating fluids

These materials are typically not required for conventional CT services. When including the additional separators and nitrogen-pumping equipment required for underbalanced drilling (UBD), the advantages related to small footprint and high mobility may no longer be the case. Numerous truckloads of equipment can take days to rig up in preparation to drill with CT.

Fig. 1 shows a purpose-built CTD rig working in Oman. Because so much equipment is necessary to handle completion pipe, allow fluid recirculation, and provide for UBD operations, the small footprint and high mobility commonly associated with CT may no longer be a valid assumption.

When CTD is the best tool for the job

However, even considering the challenges to CTD, there are certain applications in which the unique aspects and capabilities of CTD technology clearly demonstrate that it is the best tool for the job. The most common applications for directionally controlled CTD technology are re-entry drilling/sidetracking from existing wellbores (often through the existing wellbore’s production tubing) and underbalanced, managed-pressure, or low-bottomhole-pressure drilling.

Another niche market for CTD technology includes the combination of a CTD unit with a low-cost conventional rotary drilling rig. In this application, the rotary rig is used to drill a quick and simple wellbore and sets casing just above the desired zone. CT is then used to drill a small, clean penetration into the desired zone and is used to run any required completion. The following sections will further discuss CTD technology

Brief history of CTD

Drilling with CT was one of the first ideas for application of continuous workstrings dating back to:

1926 - the Bannister concept for a flexible hose drillstring 1948 - the G.D. Priestman patent application work for the more conventional reeled rigid pipe

The Bannister work involved using hose for fluid circulation with support cables attached to the sides to carry the weight. The system was reported to be technically successful but marginally reliable, and development work ceased in 1940 reportedly because of the “lack of a suitable downhole motor” for the new technology.

The G.D. Priestman patent conceived what is today considered modern CTD technology as far as the spooled tubing and operation is concerned. However, it was 25 years before the first actual steel coiled tube drilling found practical application with Flex Tube Ltd. and the Uni-Flex Rig Co. Ltd. by drilling numerous shallow gas wells in Canada. This initial rigid CTD effort was pioneered by Ben Gray through the drilling of approximately 18 wells over a 14-year period in Canada.

The flexible-hose Bannister work was followed up by R.H. Cullen in the late 1950s and early 1960s. R.H. Cullen Research came up with an armor-wrapped flexible-string drilling system that used off-the-rack types of motors and drill bits. The Cullen work improved on the original by braiding the hose to carry the “drillstring” weight.

This flexible braided hose had a 2⅝-in. outside diameter (OD) and electric-powered cable running internal to the pipe. The BHA comprised an electric motor and drill collars. R.H. Cullen drilled two separate boreholes, approximately 4¾ in. in diameter, to a depth greater than 1,000 ft.

At approximately the same time period as the Cullen work in the late 1950s and early 1960s, Inst. Français du Pétrol (IFP) also showed interest in continuous-string flexible-hose drilling technology. The IFP drilling hose was spooled up onto a reel roughly 5 in. in diameter. A four-skate injector was used to translate the spooled tubing into and out of the wellbore.

The IFP spearheaded work ran turbodrills and electric drilling motors in the BHA. In this test program, over 20,000 ft of borehole was drilled, with hole sizes ranging from 6¾ up to 12¼ in. This development effort was tested both onshore and offshore. The maximum depth reportedly drilled in the IFP project was 3,380 ft because of length restrictions of the pipe on the reel.

Advantages to the IFP flexible drillstring technology of the era included:

Reduced trip time

No connections

Continuous circulation

Improved well condition

Improved safety

Optimized elements, including:

Bit performance

Directional control

Early kick detection

Bottomhole parameter monitoring

Many of these same advantages are still touted today when discussing advantages of CTD technology when compared with conventional rotary drilling. What one mentioned IFP spooled-drillstring advantage, “better working conditions,” was based on is somewhat difficult to understand. The project was abandoned because of lack of support.

From 1964 to 1969, there was an additional spooled-drillstring development effort in the form of a consortium of different companies to develop a longer string of spooled hose. This consortium developed a larger-diameter flexible drillstring up to 12,000 ft long. Again, the power cable was run internal to the pipe, and the BHA comprised electric motors and drill collars. One borehole was drilled to 4,500 ft, but there was insufficient support for further development of this type of drilling concept in the industry at the time. Like all previous projects based on this new technology, the project was soon abandoned.

Application of spooled rigid pipe drilling (PD) systems followed the early flexible reinforced hose work. From 1976 through 1978, Ben Gray with Flex Tube Ltd. assembled Rig No. 11, which used 3,000 ft of 2⅜-in. OD butt-welded X-42 line pipe. This coiled-steel drillstring was spooled onto a 13-ft diameter reel, and this apparatus was used to drill shallow gas wells in Canada. The BHA reportedly comprised three 4¾-in. drill collars, a 5-in. downhole PD motor and a 6⅝-in. tricone bit. A sixteen near-vertical, nonsteered wells were drilled, with the deepest being approximately 1,700 ft. It is important to note that Flex Tube Ltd. had also constructed a string of spooled aluminum drillpipe for this new drilling technology toward the end of this pioneering development period, but it was not placed in service.

The reasons cited for the need for this continuous drillstring included:

Escalating pipe prices

Expensive handling equipment

Eliminating need to handle heavy 30-ft pipe joints

Eliminating two men per shift

At this time the industry had problems attaining people “capable and willing to do a good job” because “long hours requiring physical and mental endurance make [the oil industry] an unattractive career.”[1]

The first two aforementioned reasons do not appear to fit the current CT market in that CT is an expendable that typically costs more than oil country tubular goods (OCTGs) and that CT handling equipment prices have come up similar to other options. However, it is hard to disagree with the logic of the last two reasons.

The roughly one-half century of spooled-drillstring technology development reportedly ended due to:

Lack of petroleum industry sponsorship for high-tech ventures

Competitive market

Fully depreciated rigs

Proven rig technology

The fact that CTD benefits did not translate into immediate cost savings

The new era of CTD

Following the initial Canadian spooled rigid pipe work, little activity occurred until 1991, when interest in the technology was again piqued and CTD began anew in France and west Texas. This renewed interest continues today in niche markets throughout the world.

As of 2003, approximately 12 years have passed from this renaissance of CTD. Out of a fleet of approximately 1,100 CT units in the world today, approximately 60 to 100 of the CT units are considered applicable for CTD, depending on reel capacity and numerous other needs and logistics limiting parameters.

The total 2002 CT-drilling-based revenues are estimated to be approximately U.S. $43,000,000, while drilling revenues are estimated at approximately U.S. $4,000,000,000. The CTD market is then estimated to be about ½ to 3% (depending on using only the CTD portion of revenue or entire job costs) of rotary-drilling-based on revenues.

Interestingly, a market survey in 1994 put the market share somewhat less than 1%. As can be seen, the revenue growth in this industry has been flat over the last decade. However, CTD does offer some unique advantages to other options, and it does come with distinct disadvantages as well.

Advantages to CTD

Underbalanced drilling

The ability to work with surface pressure while flowing produced fluids and continuously pumping when tripping into and out of the hole clearly represent the most important advantage to CTD. This unique ability allows for maintaining underbalanced conditions on the formation to minimize the potential for formation damage and increase drilling penetration rate. Maintaining underbalanced conditions on the reservoir at all times is critical in reducing the potential for formation damage in sensitive reservoirs. The majority of CTD operations performed in Canada are primarily for this reason.

Managed pressure drilling

Again, the ability to work with surface pressure gives a unique advantage to the CTD process. Experienced coiled tubing unit (CTU) crews are well trained in working with surface pressure, and the CT equipment is designed to work with significant surface pressure. Once the BHA is pressure deployed, commonly done with a lubricated wireline rig up and deployment BOPs, there is no need to snub or strip connections through a rotary BOP stripper. This capability, combined with reduced pipe handling, helps increase the safety of the operation and minimizes the risk of spills.

CT provides continuous use of hardwired telemetry and conduits

As previously mentioned, CT can have electric logging line or other signal telemetry options installed that are fully operational even while tripping. These power and signal paths significantly increase the communication bandwidth available for bidirection telemetry. The hardwired telemetry data transmission rates surpass any mud pulse telemetry, allowing greater data acquisition while drilling. Hardwired telemetry also allows deeper attainable communications than other technologies, such as electromagnetic telemetry. These power and signal paths significantly increase the communication bandwidth available for bidirectional telemetry. Other pressure conduit(s), such as small capillary tubing, are often installed in CTD reels, which enable the unique capabilities for operating downhole tools.

Fully contained well pressure

CTD operations are most often performed with fully contained well pressure via the well control stack, including a lubricator and upper stripper of hydraulic packoff. This mechanical pressure-control system is often considered a part of the primary well control as opposed to the drilling fluid in most conventional rotary-drilling operations. In properly designed and engineered jobs, taking a kick is not as much of a threat to manpower and equipment as in common rotary drilling operations.

Small footprint and greater mobility

Many of the more recent CTD programs ranging from the McKittrick work in California during 1994 to the Cerro Dragon work in Argentina during 2001 chose this method over more conventional rotary equipment because of the smaller footprint and ease of mobility of CTD equipment.

Quicker trip times

The CTD program in Alaska is arguably the most successful continuous CTD program in the world to date. The CTD program has been operating uninterrupted for over 10 years, and yet the vast majority of the jobs are performed overbalanced. The reasons for this are simple. Many formations will not support underbalanced conditions, and CT drilled boreholes have been shown to be less expensive than rotary-drilled wells, both from a cost-per-well and cost-per-barrel perspective. The quicker trip times allow for lower-cost penetrations when multiple trips and encountering unexpected geological formation changes require operational flexibility and increase the potential for changing the target and trajectory.

Potentially fewer service personnel are needed

This is not always the case, but generally speaking, CTD operations require fewer service personnel because of the reduction in pipe-handling requirements. This again, helps lower the cost of the well on a daily basis.

Disadvantages to CTD techniques

Inability to rotate

The inability to rotate the pipe accounts for the largest single disadvantage to CTD technology. Running drilling operations in 100% slide mode would be the closest analogy to understanding CTD limitations. This inability to rotate reduces:

The ability to prevent cuttings beds uphole

Achievable depths

Tolerance of solids in the drilling fluid

The buildup of solids beds requires numerous short trips to stir the cuttings bed back into the drilling fluid. In Alaska, short trips to prevent “duning” in the high angle to horizontal sections of the wells account for more than nine times the drilling penetration measured depths. On-bottom testing has confirmed that rotation and short tripping are virtually the only two ways to effectively remove solids beds once they have been deposited in the wellbore above the BHA.

Some work has been applied to designing CT equipment that can be rotated, but the CT will be able to withstand the abrasive environment typical in many rotary-drilling operations. Maximum depths achievable in high-angle to horizontal holes are reduced in a large part because of the increased friction of being in essentially static rather than dynamic mode as when the drillpipe is rotated.

When drilling overbalanced, differential pressure can increase the chance of differentially sticking the drillstring or BHA. This is particularly true for CTD for a number of reasons. First, CT is run in essentially buckled mode because of residual stresses in the CT, even when low to moderate tensile loads are present in the CT string. This, coupled with the lack of standoff normally provided by the drillpipe connections, increases the surface area of the drillstring to differential sticking. Solids accumulation within the drilling fluid system further exasperates this sticking tendency. Field data have shown that drilling efficiency is greatly reduced as solids loading in the drilling fluid approached 1%.

Cost of consumables

Jointed drillpipe can be maintained for a relatively long life by having connections recut and resurfaced, or damaged joints may simply be replaced by another 30-ft joint. CT, on the other hand, is a consumable commodity.

Unlike drillpipe, CT is plastically yielded 6 times every round trip in the hole. After a finite number of trips into the hole, the entire CT string is scrapped or sold for less severe applications. This price differential can be compounded by the fact that CT typically cost more per foot than OCTG products of similar size and weight. Because the probability of having a pinhole or parted CT is higher than in a properly maintained drillpipe, a well-defined contingency plan for such an occurrence is essential. A downhole motor is required for all CTD operations because no current method of rotating CT has been applied in the field. This adds to the cost per foot.

Limited drilling-fluids life

As previously mentioned, CTD requires a low-solids loading in the drilling fluid to:

Provide the highest weight on bit (WOB)

Assure adequate rate of penetration (ROP)

Maximize the potential reach

Relatively low achievable CTD pump rates often mandate relatively high viscosity to assure adequate hole cleaning. This high viscosity often exceeds a low shear-rate viscosity (LSRV) of 40,000 or more and tasks the ability of solids-control equipment to efficiently remove solids. Finally, the high friction losses and associated turbulence degrade many common biopolymers used in CTD applications. All these factors result in higher costs to maintain a drilling-fluid system.

Limited equipment and limited experience manpower base

As previously discussed, the limited equipment base and lack of widespread application of CTD technology limit the availability of equipment and experienced manpower. These factors often result in higher-cost operations, and because the experience base is not nearly as high as that for rotary technology, the potential also exists for reduced chance factor of success in some instances.

Logistics of getting equipment to the work location

Drilling requires a conduit to carry drilling fluids at a sufficient rate to lubricate and cool the bit and remove the cuttings at the depth required to reach the desired targets. The higher the achievable pump rate, the more efficient the cutting-transport back to the surface. Generally, a relatively large-diameter conduit is more desirable. The target depth is fixed. Almost without exception, all the CT required to drill a well is spooled up onto a single drum.

The needs for hole cleaning and reaching the required depth often result in relatively large reels of CT, which make the logistics of getting the equipment to many potential drillsites problematic. Meeting road restrictions is a challenge for many on-site locations, and the offshore arena has its own set of equal or more challenging logistic problems. Not only is room at a premium, but, also, cranes needed to lift the spools of CT are often inadequate. These and other problems require more preplanning, engineered solutions, and often butt-welds in the CT. As previously mentioned, butt-welds significantly reduce the available useful life of a reel of CT that is already a consumable.

Reduced pump rates, torque, and WOB

This is not unique to CTD operations. Drilling operations encounter the same limits when they are performed with small-diameter drillstring similar to most common CTD operations.

More tortuous path

Currently, CT cannot be rotated to drill the reach and horizontal sections of horizontal and high-angle holes. However, new technology is currently under development and is expected to offer some relief with the ability to continuously rotate portions of the BHA to provide a smoother trajectory.

Newer technology with lack of operator experience base

Rotary drilling is a proven technology with reasonably well understood capabilities and limitations. This can be said for CTD only in a few geographic locations where CTD is continuously used, such as Alaska and Canada.

Selling CTD technology in a new location is a difficult proposition, owing in part to the truth of the following quote: “Bad memories die hard in the oil field, and many remain suspicious of the technology. Because the reputation of a project engineer or manager is always on the line, it is natural to choose the proven over the new, potentially risky technique, regardless of potential cost savings.”.[3] Despite these limitations, the unique advantages to CTD technology often outweigh the disadvantages.

CTD equipment

There is the common belief that CTD equipment is compact and highly mobile. In reality, the equipment required to provide drilling functions can make this a misconception. CTD ancillary equipment needs do not significantly differ from those of jointed-pipe or rotary-drilling operations. CTD mechanics and limitations are the same as when slide drilling with rotary-drilling units. The similarities between CTD and jointed-pipe drilling in needed equipment far outweigh the differences.

Current CTD is based on the same equipment used in rotary drilling with small-diameter drillstrings. The orienter in the BHA is the only unique CTD equipment required for directional drilling other than common CT ancillary equipment, such as:

Connectors

Flapper check valves

Disconnects and circulation subs

With the exception of the CT itself, all other drilling physics and required equipment is the same as slide drilling with jointed pipe. Fig. 2 shows an example of mud pulse telemetry CTD BHA.

Fig. 2—Mud-pulse telemetry CTD BHA. Frictional pressure drop through the CT can be significantly reduced and problem contingencies are increased when compared to wire- or umbilical-containing CT. Data transmission, however, is significantly slower than wireline telemetry options and is not compatible with compressible gas within the CT.

Fig. 3 shows an example of a modular CTD BHA that relies on an electric line installed within the CT for telemetry. Although differential pressure drop through the CT is higher than CT without wire installed, this type of BHA has proven to be efficient in CTD applications.

Fig. 3—Modular CTD BHA that relies on an electric line installed within the CT for telemetry. Although differential pressure drop through the CT is higher than CT without wire installed, this type of BHA has proven to be efficient in CTD applications. Electric line telemetry will operate with gas phases within the CT as commonly used in underbalanced drilling applications (courtesy of Baker Hughes Inteq.)

The orienter

The orienter, as the name suggests, provides a method to orient the toolface of the bottomhole drilling assembly. Early orienters included a design with a lead screw that would provide a rotational torque to the BHA when the pumps were off and slackoff weight was varied—much like the operation of a small child’s mechanical top. The new orientation was locked in once circulation was started again.

The next improvement in orienting tools was indexing tools. These tools were operated by alternating the pumps on and off to index the orienter in typically 30 to 60° steps. These early orienters were often slow and less than optimally reliable, but they did and still do provide a method to directionally steer a mud-pulse BHA where no wires or umbilicals are installed inside the CT.

The most recent design of an orienter for mud-pulse-directional drilling included use of a smart sub that can recognize words pumped downhole by varying the pump rate, decipher the words, and then rotate the BHA to the requested tool face.

The other category of orienters includes those that are wireline or hydraulically operated. Using these tools requires the inclusion of wire and/or one or more small-diameter umbilicals installed inside the CT. The wires and/or umbilicals reduce the effective CT inside diameter (ID), causing increased frictional pressure losses in the CT, and add more weight per foot. Typically, these electric or hydraulically operated orienters have a range of rotation of approximately 400°. However, these tools have provided much more predictable results, and the high-rate telemetry path of installed wireline has proven to outweigh the disadvantages to their use. Often overlooked potential problems with CT containing umbilical or wire include:

The contingency to cut the CT should the BHA or CT become stuck

Restrictions to pumping balls or darts through the CT

CTD unit

Many, if not most, drilling applications require cleaning and recirculation of viscosified drilling fluid and call for completing the zone drilled with some type of tubulars. The vast majority of common CT units are designed to effectively run CT into and out of live wells. They are not designed to handle jointed pipe and typically carry no fluid-handling equipment.

There are numerous methods used to provide needed drilling and completion capabilities during CTD operations. Many CTD service providers combine CT equipment with common drilling components including substructures, pipe-handling equipment, drilling-fluid handling and solids-removal equipment, and some sort of mast or vertical support.

Occasionally, CTD service providers simply rig up a coiled tubing drilling unit (CTDU) with a workover or drilling rig. Others build new equipment custom designed to meet the restrictions and needs of areas in which they operate. (See Fig. 4).

Fig. 4—Purpose built CTD rig working in Canada. These rigs are often built considering local area needs and regulations. This rig includes equipment for deploying BHAs into a pressurized wellbore (courtesy of BJ CT Services).

Hybrid CTDUs are available in several locations worldwide that combine CT equipment with a drilling or completion rig in an integrated package. These hybrid CTDUs are as efficient drilling with CT as they are in handling pipe or performing other common drilling, completion, and workover functions. However, with the versatility often come higher day rates and a larger and heavier equipment spread. Fig. 5 shows an example of a hybrid CTDU that provides all common drilling rig functions and efficient CTD. These hybrid units are extremely efficient and operationally flexible but can weigh well over 1.5 million pounds.

Fig. 5—Example of hybrid CTD unit that provides all common drilling rig functions and efficient CT drilling (courtesy of Schlumberger).

Guidelines for successfully applying CTD technology

Although a number of operators ranging in several geographical areas have successfully applied CTD technology, its widespread use still has not been accepted. Reasons for this are numerous, with the most common probably being lack of commitment to get over the learning curve and into the exploitation mode. The following is a list of things an engineer can do to help assure a successful CTD program:

Have the correct target and keep it simple:

Proper reservoir

Low difficulty

Lower-challenge drilling especially for wells early in the program

Drillability considering the confines of slide drilling with small tubing

Have the correct program size:

Enough candidate wells to get over the learning curve and into exploitation

Have the correct equipment for the effort

Have the commitment:

Management and technology resources from both operator and service provider

When bringing CTD into a new area, plan on using sound engineering concepts combined with extensive preparation and planning. It is imperative to remember that CTD drilling technology is still a drilling function that relies on the same best practices for drilling. Pull together a multiexperienced crew that knows CT and drilling practices. Prepare and train for numerous contingencies. Read all available technical papers on CTD.

The following is a list of items to consider and parameters that are within the abilities of CTD technology. None of these are “records.” Instead, they fall in the middle of what can be accomplished using proper CTD techniques.

3,000 ft or less measured-depth laterals kicking off at 10,000 ft measured depths.

Plan on less than 55° per 100 ft build sections.

When drilling in 4-½ in. casing, the most common CT size used is 2-⅜ in. or 2-⅝ in that hydraulically fits the bit for the casing size.

In 5-½ in. casing, the most commonly used CT sizes range from 2-⅜ in. to 3-1/16 in., again with the 3-1/16 in. CT optimized for hydraulic requirements.

In 3-½ in. casing, the most common CT size is 2 in. OD.

The following is a list of where CTD technology may be applicable:

Underbalanced (UB) drilling to minimize potential damage to the formation.

Where costs to mobilize rotary rigs are high.

Areas with campaign number of candidates.

Where logistics/area for rig may be tight.

Managed pressure drilling candidates.

Through faults with high differential pressure between zones.

In stable wells where ROP dramatically increases during UB drilling.

Areas with access to:

Right well candidates

Drillable formations within CT range

Personnel

Right people with the right skill sets doing the right thing

Right equipment available

Properly applied, CTD’s unique capabilities can be used to provide reliable and repeatable drilling solutions, even in demanding circumstances.

CTD tools, techniques, and equipment under development

Currently there are numerous ideas in various stages of development that may extend the utilization of CT for drilling operations. These new developments in technology, techniques, and/or equipment target special needs:

Include telemetry built into the CT string such as used in the Halliburton Anaconda Project. The Anaconda CT was made of composites and contained numerous conductors wound into the composite body. The composite material reduced needed crane load capacities and extended the CT fatigue life. The built-in conductors allowed for power and telemetry without intrusion into the inner diameter of the CT.

Special designed equipment and techniques to reduce costs for exploiting existing brownfield assets.

More-compact and lighter units for more flexible movement on existing roadways.

Equipment to efficiently drill smaller-diameter wells, for both directional and nonsteered applications.

Offshore packages for CTD intervention. This equipment is designed to address problems common to offshore environments including limited deck space, limited crane capacities, heave and swell problems, and time required to rig up and test equipment.

Only time will tell if this equipment can be successfully developed and applied to extend the utility of CTD or if these new ideas will disappear into obscurity, as have many of the early innovations in continuous conduit drilling.